Techno-economic optimization of wind energy based hydrogen refueling station case study Salalah city Oman

Clean energy resources will be used more for sustainability improvement and durable development. Efficient technologies of energy production, storage, and usage results in reduction of gas emissions and improvement of the world economy. Despite 30% of electricity being produced from wind energy, the connection of wind farms to medium and large-scale grid power systems is still leading to instability and intermittency problems. Therefore, the conversion of electrical energy generated from wind parks into green hydrogen consists of an exciting solution for advancing the development of green hydrogen production, and the clean transportation sector. This paper presents a techno-economic optimization of hydrogen production for refueling fuel cell vehicles, using wind energy resources. The paper analyses three configurations, standalone Wind-Park Hydrogen Refueling Station (WP-HRS) with backup batteries, WP-HRS with backup fuel cells, and grid-connected WP-HRS. The analysis of different configurations is based on the wind potential at the site, costs of different equipment, and hydrogen load. Therefore, the study aims to find the optimized capacity of wind turbines, electrolyzers, power converters, and storage tanks. The optimization results show that the WP-HRS connected to the grid has the lowest Present Worth Cost (PWC) of 6,500,000 €. Moreover, the Levelized Hydrogen Cost (LHC) of this solution was found to be 6.24 €/kg. This renewable energy system produces 80,000 kg of green hydrogen yearly.     

Techno-economic analysis of photovoltaic-hydrogen refueling station case study: A transport company Tunis-Tunisia

This paper sheds the light on the future of green hydrogen in Tunisia. So, a detailed economic assessment and evaluation of the Levelized Hydrogen Cost (LHC) and the Net Profit (NP) of a Photovoltaic (PV) Hydrogen Refueling Station (HRS) are presented and discussed. Tunisia is characterized by its high PV potential which makes the production of electricity from solar energy an effective alternative source. However, due to the regulations and issues related to the connection of medium PV scale to the power grid, the energy produced from renewable sources (RS) is still less than 3% of the total produced electricity. On the other hand, the price of hydrocarbon fuels is still increasing. The gap between production and total demand in hydrocarbons has created a deficit in the primary energy balance. Therefore, the production of hydrogen from solar energy for refueling Fuel Cell Vehicles (FCV)s consists of a promising solution to boost the development of the country, reduce hydrocarbon fuels consumption, and protect the environment. The sizing of a small PV-HRS to produce 150 kg of hydrogen per day shows the necessity to install PV systems with a total Direct Current (DC) capacity of 1.89 MWp. The Initial Cost (IC) analysis shows that while the PV system cost represents 48.5% of the total IC, the IC of electrolysers represents 41%. The storage system cost is approximately equal to 3.2% of the total IC. The LHC is equal to 3.32€/kg with a total IC of 2.34 million €.     

Analyzing the levelized cost of hydrogen in refueling stations with on-site hydrogen production via water electrolysis in the Italian scenario

Hydrogen refueling infrastructures with on-site production from renewable sources are an interesting solution for assuring green hydrogen with zero CO₂ emissions. The main problem of these stations development is the hydrogen cost that depends on both the plant size (hydrogen production capacity) and on the renewable source.In this study, a techno-economic assessment of on-site hydrogen refueling stations (HRS), based on grid-connected PV plants integrated with electrolysis units, has been performed. Different plant configurations, in terms of hydrogen production capacity (50 kg/day, 100 kg/day, 200 kg/day) and the electricity mix (different sharing of electricity supply between the grid and the PV plant), have been analyzed in terms of electric energy demands and costs.The study has been performed by considering the Italian scenario in terms of economic streams (i.e. electricity prices) and solar irradiation conditions.The levelized cost of hydrogen (LCOH), that is the more important indicator among the economic evaluation indexes, has been calculated for all configurations by estimating the investment costs, the operational and maintenance costs and the replacement costs.Results highlighted that the investment costs increase proportionally as the electricity mix changes from Full Grid operation (100% Grid) to Low Grid supply (25% Grid) and as the hydrogen production capacity grows, because of the increasing in the sizes of the PV plant and the HRS units. The operational and maintenance costs are the main contributor to the LCOH due to the annual cost of the electricity purchased from the grid.The calculated LCOH values range from 9.29 €/kg (200 kg/day, 50% Grid) to 12.48 €/kg (50 kg/day, 100% Grid).     

Analytical model for a techno-economic assessment of green hydrogen production in photovoltaic power station case study Salalah city-Oman

Hydrogen energy will play a credible role to reduce gas emissions in the transportation sector, the storage of energy, and other industrial applications. Moreover, the hydrogen produced from renewable energy sources allows to minimize greenhouse gas and increase the net profit of energy projects. This paper discusses the feasibility of the conversion of solar energy into hydrogen in a Photovoltaic Hydrogen Station (PVHS) in the south of Oman. Then, the sizing of different equipment and hydrogen production estimation in a 5 MWp PVHS is presented. The analysis of the investment cost (IC), the Net Profit (NP), and the Levelized Hydrogen Energy Cost (LHEC) are discussed to investigate the benefit of the project. The energy generated from the PV system and the produced hydrogen is calculated through an analytical model. The PVHS consists of 5 MWp PV panels connected to electrolyzers through maximum power point-controlled converters. The electrolyzers convert the electrical energy and the water into hydrogen. The hydrogen compressed and stored in special tanks can be used later in many industrial applications. The system produces about 90 910 kg of hydrogen per year with an IC of 5 301 760 €. The calculated LHEC is equal to 6.2 €/kg at an interest rate of 2%. The analysis has shown promising green hydrogen production projects in Oman.     

Assessment of offshore liquid hydrogen production from wind power for ship refueling

Green hydrogen from electrolysis has become the most attractive energy carrier for making the transition from fossil fuels to carbon-free energy sources possible. Especially in the naval sector, hydrogen has the potential to address environmental targets due to the lack of low-carbon fuel options. This study aims at investigating an offshore liquefied green hydrogen production plant for ship refueling. The plant comprises a wind farm for renewable electricity generation, an electrolyzer stack for hydrogen production, a water treatment unit for demineralized water production, and a hydrogen liquefaction plant for hydrogen storage and distribution to ships. A pre-feasibility study is addressed to find the optimal capacities of the plant that minimize the payback time. The model results show that the electrolyzer capacity shall be set equal to a value between 80% and 90% of the wind farm capacity to achieve the minimum payback times. Additionally, the wind farm capacity shall be higher than about 150 MW to limit the payback time to values lower than 11 years for a fixed hydrogen price of 6 €/kg. The Levelized Cost of Hydrogen results to be below 4 €/kg for a wide range of plant capacities for a lifetime of the plant of 25 years. Thus, the model shows that this plant is economically feasible and can be reproduced similarly for different locations by rescaling the different selected technologies. In this way, the naval sector can be decarbonized thanks to a new infrastructure for the production and refueling of liquified green hydrogen directly provided on the sea.     

Centralized and decentralized electrolysis-based hydrogen supply systems for road transportation – A modeling study of current and future costs

This work compares the costs of three electrolysis-based hydrogen supply systems for heavy road transportation: a decentralized, off-grid system for hydrogen production from wind and solar power (Dec-Sa); a decentralized system connected to the electricity grid (Dec-Gc); and a centralized grid-connected electrolyzer with hydrogen transported to refueling stations (Cen-Gc). A cost-minimizing optimization model was developed in which the hydrogen production is designed to meet the demand at refueling stations at the lowest total cost for two timeframes: one with current electricity prices and one with estimated future prices. The results show that: For most of the studied geographical regions, Dec-Gc gives the lowest costs of hydrogen delivery (2.2–3.3€/kgH₂), while Dec-Sa entails higher hydrogen production costs (2.5–6.7€/kgH₂). In addition, the centralized system (Cen-Gc) involves lower costs for production and storage than the grid-connected decentralized system (Dec-Gc), although the additional costs for hydrogen transport increase the total cost (3.5–4.8€/kgH₂).     

Assessment of hydrogen as a potential energy storage for urban areas’ PV-assisted energy systems - Case study

The world is experiencing unprecedented development in the clean energy sector in residential and industrial applications. This paper provides a case study assessing different scenarios of greenizing the electrical energy demand in El-Mostakbal city in Egypt. Three scenarios are studied with consideration of a photovoltaic (PV) system integrated with the grid-connected city with different integrated system configurations. The scenarios for the grid-connected city are scenario-I: only PV, scenario-II: PV with batteries for electricity storage along with grid electricity, and scenario-III: PV with hydrogen production, storage, and utilization for covering the electric demand along with grid electricity, these scenarios are assessed technoeconomically, and the results show an optimized case where the electricity demand of the city can be met with 64.3% produced from solar energy, at $71.7 M of the net present cost.     

Cost of a potential hydrogen-refueling network for heavy-duty vehicles with long-haul application in Germany 2050

Long-distance road-freight transport emits a large share of Germany's greenhouse gas (GHG) emissions. A potential solution for reducing GHG emissions in this sector is to use green hydrogen in fuel cell electric vehicles (FC-HDV) and establish an accompanying hydrogen refueling station (HRS) network. In this paper, we apply an existing refueling network design model to a HDV-HRS network for Germany until 2050 based on German traffic data for heavy-duty trucks and estimate its costs. Comparing different fuel supply scenarios (pipeline vs. on-site), The on-site scenario results show a network consisting of 137 stations at a cost of 8.38 billion € per year in 2050 (0.40 € per vehicle km), while the centralized scenario with the same amount of stations shows a cheaper cost with 7.25 billion euros per year (0.35 € per vehicle km). The hydrogen cost (LCOH) varies from 5.59 €/kg (pipeline) to 6.47 €/kg (on-site) in 2050.     

Utilization of renewable hybrid energy for refueling station in Al-Kharj,Saudi Arabia

Hydrogen is one of the energy carriers that can be produced using different techniques. Combining multiple energy sources can enhance hydrogen production and meet other electrical demands. The hybrid arrangement allows the produced hydrogen to be stored and used when the electrical energy sources are not adequate. In this study, utilizing the meteorological data was investigated using HOMER (Hybrid Optimization of Multiple Energy Resources) software for the optimal solution. The results demonstrated that the “best-optimized system has 270 kW of photovoltaic (PV), 1 unit of 300 kW of wind turbine (WT), 500 kW of electrolyzer, 100 kg/L of the hydrogen tank, 70 units of 1 kWh lithium-ion battery, and 472 kW of the converter. The selected hybrid energy system has the lowest Levelized cost of energy (LCOE), Levelized cost of hydrogen (LCOH), and net present cost (NPC) of $/kg 0.6208, $/kg 9.34, and $ 484,360.00 respectively which judged the system to be the best choice for the proposed hydrogen project in AI-Kharj. This investigation will help stakeholders and policymakers optimize hybrid energy systems that economically meet the hydrogen production and refueling station demands of the AI-Kharj community.     

Techno-economic assessment of green hydrogen valley providing multiple end-users

A techno-economic analysis of a hydrogen valley is carried out in this paper. A hydrogen generator fed by a wind farm (WF) and/or a photovoltaic (PV) plant supplies four end-users: a stationary fuel cell, a hydrogen refuelling station, the injection in the natural gas pipeline and, in case of sufficient hydrogen surplus, a biological hydrogen methanation (BHM) process.The results demonstrated that an efficiency improvement and a reduction in hydrogen production costs arise from a balanced supply from wind and solar energy. Without the inclusion of a BHM process, hydrogen production costs lower than 7 €/kg were achieved by a hydrogen generator using 10–12% of the PV + WF annual energy with a PV share of 20%–50%. The hydrogen production costs were further reduced to 5 €/kg by introducing a BHM process and increasing the percentage of electrical energy supplied by the PV + WF system to 25% of its overall production.     

Hydrogen supply scenarios for a climate neutral energy system in Germany

A climate neutral energy system in Germany will most likely require green hydrogen. Two important factors, that determine whether the hydrogen will be imported or produced locally from renewable energy are still uncertain though - the import price for green hydrogen and the upper limit for photovoltaic installations. To investigate the impact of these two factors, the authors calculate cost optimized climate neutral energy systems while varying the import price from 1.25 €/kg to 5 €/kg with unlimited import volume and the photovoltaic limit from 300 GW to unlimited. In all scenarios, hydrogen plays a significant role. At a medium import price of 3.75 €/kg and photovoltaic limits of 300–900 GW the hydrogen supply is around 1200 to 1300 TWh with import shares varying from 60 to 85%. In most scenarios the electrolysis profile is highly correlated with the photovoltaic power, which leads to full load hours of 1870 h–2770 h.     

Techno-economic evaluation of hydrogen refueling stations with liquid or gaseous stored hydrogen

In this study, different hydrogen refueling station (HRS) architectures are analyzed energetically as well as economically for 2015 and 2050. For the energetic evaluation, the model published in Bauer et al. [1] is used and norm-fitting fuelings according to SAE J2601 [2] are applied. This model is extended to include an economic evaluation. The compressor (gaseous hydrogen) resp. pump (liquid hydrogen) throughput and maximum pressures and volumes of the cascaded high-pressure storage system vessels are dimensioned in a way to minimize lifecycle costs, including depreciation, capital commitment and electricity costs. Various station capacity sizes are derived and energy consumption is calculated for different ambient temperatures and different station utilizations. Investment costs and costs per fueling mass are calculated based on different station utilizations and an ambient temperature of +12 °C. In case of gaseous trucked-in hydrogen, a comparison between 5 MPa and 20 MPa low-pressure storage is conducted. For all station configurations and sizes, a medium-voltage grid connection is applied if the power load exceeds a certain limit. For stations with on-site production, the electric power load of the hydrogen production device (electrolyzer or gas reformer) is taken into account in terms of power load. Costs and energy consumption attributed to the production device are not considered in this study due to comparability to other station concepts. Therefore, grid connection costs are allocated to the fueling station part excluding the production device. The operational strategy of the production device is also considered as energy consumption of the subsequent compressor or pump and the required low-pressure storage are affected by it. All station concepts, liquid truck-supplied hydrogen as well as stations with gaseous truck-supplied or on-site produced hydrogen show a considerable cost reduction potential. Long-term specific hydrogen costs of large stations (6 dispensers) are 0.63 €/kg – 0.76 €/kg (dependent on configuration) for stations with gaseous stored hydrogen and 0.18 €/kg for stations with liquid stored hydrogen. The study focuses only on the refueling station and does not allow a statement about the overall cost-effectiveness of different pathways.     

Decarbonising city bus networks in Ireland with renewable hydrogen

This paper presents techno-economic modelling results of a nationwide hydrogen fuel supply chain (HFSC) that includes renewable hydrogen production, transportation, and dispensing systems for fuel cell electric buses (FCEBs) in Ireland. Hydrogen is generated by electrolysers located at each existing Irish wind farm using curtailed or available wind electricity. Additional electricity is supplied by on-site photovoltaic (PV) arrays and stored using lithium-ion batteries. At each wind farm, sizing of the electrolyser, PV array and battery is optimised system design to obtain the minimum levelised cost of hydrogen (LCOH). Results show the average electrolyser capacity factor is 64% after the integration of wind farm-based electrolysers with PV arrays and batteries. A location-allocation algorithm in a geographic information system (GIS) environment optimises the distributed hydrogen supply chain from each wind farm to a hypothetical hydrogen refuelling station in the nearest city. Results show that hydrogen produced, transported, and dispensed using this system can meet the entire current bus fuel demand for all the studied cities, at a potential LCOH of 5–10 €/kg by using available wind electricity. At this LCOH, the future operational cost of FCEBs in Belfast, Cork and Dublin can be competitive with public buses fuelled by diesel, especially under carbon taxes more reflective of the environmental impact of fossil fuels.     

Simulation and optimization of stand-alone hybrid renewable energy systems

Stand-alone hybrid renewable energy systems usually incur lower costs and demonstrate higher reliability than photovoltaic (PV) or wind systems. The most usual systems are PV–Wind–Battery and PV–Diesel–Battery. Energy storage is usually in batteries (normally of the lead-acid type). Another possible storage alternative, such as hydrogen, is not currently economically viable, given the high cost of the electrolyzers and fuel cells and the low efficiency in the electricity–hydrogen–electricity conversion. When the design of these systems is carried out, it is usually done resolve an optimization problem in which the Net Present Cost (NPC) is minimized or, in some cases, in relation to the Levelized Cost of Energy (LCE). The correct resolution of this optimization problem is a complex task because of the high number of variables and the non-linearity in the performance of some of the system components. This paper revises the simulation and optimization techniques, as well as the tools existing that are needed to simulate and design stand-alone hybrid systems for the generation of electricity.     

Design of hybrid power-to-power systems for continuous clean PV-based energy supply

The increasing penetration of intermittent renewable sources, fostering power sector decarbonization, calls for the adoption of energy storage systems as an essential mean to improve local electricity exploitation, reducing the impact of distributed power generation on the electric grid. This work compares the use of hydrogen-based Power-to-Power systems, battery systems and hybrid hydrogen-battery systems to supply a constant 1 MW_el load with electricity locally generated by a photovoltaic plant. A techno-economic optimization model is set up that optimizes the size and annual operation of the system components (photovoltaic field, electrolyzer, hydrogen storage tanks, fuel cell and batteries) with the objective of minimizing the annual average cost of electricity, while guaranteeing an imposed share of local renewable self-generation. Results show that, with the present values of investment costs and grid electricity prices, the installation of an energy storage system is not economically attractive by itself, whereas the installation of PV panels is beneficial in terms of costs, so that the baseline optimal solution consists of a 4.2 MW_p solar field capable to self-generate 33% of the load annually. For imposed shares of self-generation above 40%, decoupling generation and consumption becomes necessary. The use of batteries is slightly less expensive than the use of hydrogen storage systems up to a 92% self-generation rate. Above this threshold, seasonal storage becomes predominant and hybrid storage becomes cheaper than batteries. The sale of excess electricity is always important to support the plant economics, and a sale price reduction sensibly impacts the results. Hydrogen storage becomes more competitive when the need for medium and long terms energy shift increases, e.g. in case of having a cap on the available PV capacity.     

Parameter study for dimensioning of a PV optimized hydrogen supply plant

Green hydrogen produced from intermittent renewable energy sources is a key component on the way to a carbon neutral planet. In order to achieve the most sustainable, efficient and cost-effective solutions, it is necessary to match the dimensioning of the renewable energy source, the capacity of the hydrogen production and the size of the hydrogen storage to the hydrogen demand of the application.For optimized dimensioning of a PV powered hydrogen production system, fulfilling a specific hydrogen demand, a detailed plant simulation model has been developed. In this study the model was used to conduct a parameter study to optimize a plant that should serve 5 hydrogen fuel cell buses with a daily hydrogen demand of 90 kg overall with photovoltaics (PV) as renewable energy source. Furthermore, the influence of the parameters PV system size, electrolyser capacity and hydrogen storage size on the hydrogen production costs and other key indicators is investigated. The plant primarily uses the PV produced energy but can also use grid energy for production.The results show that the most cost-efficient design primarily depends on the grid electricity price that is available to supplement the PV system if necessary. Higher grid electricity prices make it economically sensible to invest into higher hydrogen production and storage capacity. For a grid electricity price of 200 €/MWh the most cost-efficient design was found to be a plant with a 2000 kWp PV system, an electrolyser with 360 kW capacity and a hydrogen storage of 575 kg.     

Renewable energy systems based on hydrogen for remote applications

An integrated renewable energy (RE) system for powering remote communication stations and based on hydrogen is described. The system is based on the production of hydrogen by electrolysis whereby the electricity is generated by a 10 kW wind turbine (WT) and 1 kW photovoltaic (PV) array. When available, the excess power from the RE sources is used to produce and store hydrogen. When not enough energy is produced from the RE sources, the electricity is then regenerated from the stored hydrogen via a 5 kW proton exchange membrane fuel cell system. Overview results on the performances of the WT, PV, and fuel cells system are presented.     

Investigation of photovoltaic-hydrogen power system for a real house in Turkey: Hydrogen blending to natural gas effects on system design

In the study, the effects of hydrogen mixing studies at the rate of 20% to the natural gas system which is an ongoing study in Turkey, on the photovoltaic system (PV) is investigated using a real house consumption. Providing the annual electrical energy consumption (1936,83  kWh) and 20% of natural gas consumption (62,4 m³) of a real house with hydrogen is included in the study. A PV-hydrogen system is theoretically investigated to provide the energy required for hydrogen production from solar panels. Hydrogen blending effects on PV size, capacity usage, and carbon footprint are analyzed. Thus, the contribution was also made to the “green hydrogen” works and reduction of the carbon footprint of the house. It was found that the required hydrogen for electricity can be provided 52,5 m² solar panel area and 14,28% increase in this area and installed power can provide an amount of hydrogen that need for 20% hydrogen blending to the natural gas system. The overall system capacity usage decreased when the system is used for 20% hydrogen blending to the natural gas system. The carbon footprint of the house was decreased by 67,5%. If the hydrogen has not been blended with 20% natural gas, this ratio would have been 59,2%.     

Assessing green energy growth in Nepal with a hydropower-hydrogen integrated power grid model

The involvement of green hydrogen in energy transformation is getting global attention. This assessment examines the hydrogen production and its utilization potential in one of the hydropower-rich regions, Nepal under various demand growth and technology intervention scenarios by developing a power grid model of 52 nodes and 68 transmission lines operating at an hourly time-step. The model incorporates a grid-connected hydrogen storage system as well as charging stations for electric and hydrogen vehicles. The least-costly pathways for power grid expansion at the nodal and provincial levels are identified through optimization. The results show that 32 GW of installed capacity is required to meet domestic electricity demand and 14 GW more hydropower should be exploited to completely decarbonize the transport sector by 2050. For maintaining 50% shares of hydrogen vehicle in the transport sector and meet government electricity export targets, Nepal requires 5.7 GW, 12 GW and 23 GW of the additional electrolyzer, hydrogen storage tanks and storage-based hydropower capacities respectively. For a given electricity demand, introducing hydrogen systems can reduce the capacity requirements of hydro storage by storing surplus power generated from pondage run-of-the-river and run-of-the-river hydropower during the rainy season and using it in the dry season.     

A flexible analytical model for operational investigation of solar hydrogen plants

Hydrogen will become a dominant energy carrier in the future and the efficiency and lifetime cost of its production through water electrolysis is a major research focus. Alongside efforts to offer optimum solutions through plant design and sizing, it is also necessary to develop a flexible virtualised replica of renewable hydrogen plants, that not only models compatibility with the “plug-and-play” nature of many facilities, but that also identifies key elements for optimisation of system operation. This study presents a model for a renewable hydrogen production plant based on real-time historical and present-day datasets of PV connected to a virtualised grid-connected AC microgrid comprising different technologies of batteries, electrolysers, and fuel cells. Mathematical models for each technology were developed from chemical and physical metrics of the plant. The virtualised replica is the first step toward the implementation of a digital twin of the system, and accurate validation of the system behaviour when updated with real-time data. As a case study, a solar hydrogen pilot plant consisting of a 60 kW Solar PV, a 40 kW PEM electrolyser, a 15 kW LIB battery and a 5 kW PEM fuel cell were simulated and analysed. Two effective operational factors on the plant's performance are defined: (i) electrolyser power settings to determine appropriate hydrogen production over twilight periods and/or overnight and (ii) a user-defined minimum threshold for battery state of charge to prevent charge depletion overnight if the electrolyser load is higher than its capacity. The objective of this modelling is to maximise hydrogen yield while both loss of power supply probability (LPSP) and microgrid excess power are minimised. This analysis determined: (i) a hydrogen yield of 38–39% from solar DC energy to hydrogen energy produced, (ii) an LPSP <2.6 × 10^?4 and (iii) < 2% renewable energy lost to the grid as excess electricity for the case study.